Modern wind turbines are commonly used to supply electricity into the electrical grid. Wind turbines of this kind generally comprise a rotor with a rotor hub and a plurality of blades. The rotor is set into rotation under the influence of the wind on the blades. The rotation of the rotor shaft either directly drives the generator rotor (“directly driven”) or through the use of a gearbox.
A variable speed wind turbine may typically be controlled by varying the generator torque and the pitch angle of the blades. As a result, aerodynamic torque, rotor speed and electrical power will vary.
A common prior art control strategy of a variable speed wind turbine is described with reference to FIG. 1. In FIG. 1, the operation of a typical variable speed wind turbine is illustrated in terms of the pitch angle (β), the electrical power generated (P), the generator torque (M) and the rotational velocity of the rotor (o), as a function of the wind speed (V(m/s). The curve representing the electrical power generated as a function of wind speed is typically called a power curve having a first operational range (I), a second operational range (II), a third operational range (III), and a fourth operational range (IV).
In a first operational range, from the cut-in wind speed to a first wind speed (e.g. approximately 5 or 6 m/s), the rotor may be controlled to rotate at a substantially constant speed that is just high enough to be able to accurately control it. The cut-in wind speed may be e.g. approximately 3 m/s.
In a second operational range, from the first wind speed (e.g. approximately 5 or 6 m/s) to a second wind speed (e.g. approximately 8.5 m/s), the objective is generally to maximize power output while maintaining the pitch angle of the blades constant so as to capture maximum energy. In order to achieve this objective, the generator torque and rotor speed may be varied so as keep the tip speed ratio A (tangential velocity of the tip of the rotor blades divided by the prevailing wind speed) constant so as to maximize the power coefficient Cp.
In order to maximize power output and keep Cp constant at its maximum value, the rotor torque may be set in accordance with the following equation: T=k·ω2, wherein
k is a constant, and w is the rotational speed of the generator. In a direct drive wind turbine, the generator speed substantially equals the rotor speed. In a wind turbine comprising a gearbox, normally, a substantially constant ratio exists between the rotor speed and the generator speed.
In a third operational range, which starts at reaching nominal rotor rotational speed and extends until reaching nominal power, the rotor speed may be kept constant, and the generator torque may be varied to such effect. In terms of wind speeds, this third operational range extends substantially from the second wind speed to the nominal wind speed e.g. from approximately 8.5 m/s to approximately 11 m/s.
In a fourth operational range, which may extend from the nominal wind speed to the cut-out wind speed (for example from approximately 11 m/s to 25 m/s), the blades may be rotated (“pitched”) to maintain the aerodynamic torque delivered by the rotor substantially constant. In practice, the pitch may be actuated such as to maintain the rotor speed substantially constant. At the cut-out wind speed, the wind turbine's operation is interrupted.
In the first, second and third operational ranges, i.e. at wind speeds below the nominal wind speed (the sub-nominal zone of operation), the blades are normally kept in a constant pitch position, namely the “below rated pitch position”. Said default pitch position may generally be close to a 0° pitch angle. The exact pitch angle in “below rated” conditions however depends on the complete design of the wind turbine.
The before described operation may be translated into a so-called power curve, such as the one shown in FIG. 1. Such a power curve may reflect the optimum operation of the wind turbine under steady-state conditions.
However, in non-steady state (transient) conditions, the operation may not necessarily be optimum.
As further background, basic aerodynamic behaviour of (the blades of) a wind turbine is explained with reference to FIGS. 2a-2d. 
In FIG. 2a, a profile of a wind turbine blade is depicted in operation. The forces generated by the aerodynamic profile are determined by the wind that the profile “experiences”, the effective wind speed Ve. The effective wind speed is composed of the axial free stream wind speed Va and the tangential speed of the profile Vt The tangential speed of the profile Vt is determined by the instantaneous rotor speed w and the distance to the centre of rotation of the profile, the local radius r, i.e. Vt=ω·r.
The axial free stream wind speed Va is directly dependent on the wind speed Vw, and on the speed of the wind downstream from the rotor Vdown, that is Va=½(Vw+Vdown). The axial free stream wind speed may e.g. be equal to approximately two thirds of the wind speed Vw.
The resultant wind flow, or effective wind speed Ve, generates lift L and drag D on the blade. A blade may theoretically be divided in an infinite number of blade sections, each blade section having its own local radius and its own local aerodynamic profile. For any given rotor speed, the tangential speed of each blade section will depend on its distance to the rotational axis of the hub (herein referred to as local radius).
The lift generated by a blade (section) depends on the effective wind speed Ve, and on the angle of attack of the blade (section) α, in accordance with the following formula:
      L    =                  1        2            ⁢              ρ        ·                  C          L                    ⁢                        V          e          2                ·        S              ,whereinρ is the air density, Ve is the effective wind speed, CL is the lift coefficient (dependent on the angle of attack α), and S is the surface of the blade section.
Similarly, the drag D generated by a blade section can be determined in accordance with the following equation:
      D    =                  1        2            ⁢              ρ        ·                  C          D                    ⁢                        V          e          2                ·        S              ,wherein CD is the drag coefficient dependent on the angle of attack α.
For an entire wind turbine blade, the contribution to lift and drag of each blade section should be summed to arrive at the total drag and lift generated by the blade.
Both the drag coefficient CD and the lift coefficient CL depend on the profile or the blade section and vary as a function of the angle of attack of the blade section. The angle of attack α may be defined as the angle between the chord line of a profile (or blade section) and the vector of the effective wind flow, see FIG. 2a. 
FIG. 2b illustrates in a very general manner how the lift coefficient and drag coefficient may vary as a function of the angle of attack of a blade section. Generally, the lift coefficient (reference sign 21) increases to a certain maximum at a so-called critical angle of attack 23. This critical angle of attack is also sometimes referred to as stall angle. The drag coefficient (reference sign 22) may generally be quite low and starts increasing in an important manner close to the critical angle of attack 23. This rapid change in aerodynamic behaviour of a profile or blade section is linked generally to the phenomenon that the aerodynamic flow around the profile (or blade section) is not able to follow the aerodynamic contour and the flow separates from the profile. The separation causes a wake of turbulent flow, which reduces the lift of a profile and increases the drag significantly.
The exact curves of the lift coefficient and drag coefficient may vary significantly in accordance with the aerodynamic profile chosen. However, in general, regardless of the aerodynamic profile chosen, a trend to increasing lift up until a critical angle of attack and also a rapid increase in drag after a critical angle of attack can be found.
In accordance with FIG. 2a, the tangential force generated by a blade section is given by T=L·sin(α+θ)−D·cos(α+θ), wherein θ is the pitch angle and α is the angle of attack. The pitch angle may be defined as the angle between the rotor plane and the chord line of a profile. Integrating the tangential force distribution over the radius provides the driving torque.
In order to increase the torque generated by the rotor, the angle of attack of any blade section is preferably kept below the critical angle of attack such that lift may be higher and drag may be lower.
It should be borne in mind that the angle of attack of each blade section depends on the tangential speed of the specific rotor blade section, the wind speed, the pitch angle and the local twist angle of the blade section. The local twist angle of a blade section may generally be considered constant, unless some kind of deformable blade is used. The tangential speed of the rotor blade section depends on the rotor speed (angular velocity of the rotor which is obviously the same for the whole blade and thus for each blade section) and on the distance of the blade section to the rotational axis.
For a given pitch angle, it follows that the angle of attack is determined by the tip speed ratio:
  λ  =                    ω        .        R                    V        w              .  From this, it follows that the torque generated by a rotor blade section may become a rather complicated function of the instantaneous tip speed ratio and the pitch angle of the blade.
This complicated relationship between the tip speed ratio, pitch angle, and performance of the rotor may be depicted in a three-dimensional figure, such as the one shown as FIG. 2c. 
For every rotor blade section, the torque generated may be correlated to one of the lines of FIG. 2d of constant pitch angle. These lines may be obtained by a cross-section of a three-dimensional figure such as the one shown in FIG. 2c or similar.
The lines depict the power coefficient (Cp), i.e. the ratio between the mechanical power captured by the wind turbine rotor and the available power in the wind, as a function of λ and for different pitch angles. As the power captured by the wind turbine is directly related to the generated torque, Cp curves provide information about the torque dependence on pitch angle. For each pitch angle, there is a certain critical tip speed ratio. Below this tip speed ratio, stall may occur, i.e. the angle of attack is higher than the previously mentioned critical angle of attack.
This may be illustrated in an alternative manner, such as shown in FIG. 2e. For a given tip speed ratio, e.g. λ1, there is a certain critical pitch angle θcrit, which corresponds to a critical angle of attack. Below that pitch angle, stall may occur. At the same time, at the critical pitch angle, the generated torque is maximum.
In the second operational range mentioned before, the pitch angle is generally equal to zero. For a given pitch angle, there is a certain tip speed ratio that gives the highest Cp, i.e. the most efficient operation point. In this second operational range of wind speed, the generator torque is adjusted a function of the rotor speed, in accordance with T=k·ω2. This operation is based on keeping a constant tip speed ratio and maximum CP.
In practice, instead of using measurements from an anemometer to determine the wind speed and from that the appropriate generator torque, the rotor speed is generally used. The rotor speed may be measured e.g. by measuring the generator rotor speed. In direct drive wind turbines, the rotor speed will correspond to the generator rotor speed, and in wind turbines employing a gearbox, there will generally be a fixed ratio between generator rotor speed and rotor speed.
Let's now suppose that a sudden wind speed variation occurs, e.g. a significant increase in wind speed in a relatively short time. Due to the inertia of the rotor, the rotor speed will not immediately increase. As such, the tip speed ratio of the rotor changes and the wind turbine will not be operating at maximum Cp until the rotor is capable of adapting its speed to said new wind conditions. In an even worse scenario, turbulent wind conditions with continuously varying wind speeds might exist. In such case, the inertia of the rotor does not permit tracking of the wind speed at any time, so the wind turbine will not be operating at maximum Cp unless said wind turbulence decreases. Wind energy that could be converted into electrical energy is thus being lost. It is important to bear in mind that the second operational range may occur relatively frequently throughout a wind turbine's life, so a suboptimum operation in this range may have significant effects.
There still exists a need for a method of operating a wind turbine that at least partially reduces the aforementioned problems.